1. Field of the Invention
In one aspect, this invention relates to a method for purification of a gaseous hydrocarbon stream contaminated with sulfur compounds. In another aspect, this invention relates to a process for reducing the concentration of carbonyl sulfide in refinery fuel gas. In still another aspect, this invention relates to an apparatus for hydrolysis of carbonyl sulfide to hydrogen sulfide and carbon dioxide.
2. Description of the Related Art
Refinery fuel gases are produced in a variety of thermal and catalytic cracking units, including fluid catalytic crackers, hydrocrackers, delayed cokers and the like. Fuel gases have long been burned in refineries to fire heaters for furnaces, reboilers, and the like.
Such fuel gases may contain a variety of sulfur-containing compounds such as hydrogen sulfide, carbonyl sulfide, dimethyl sulfide, diethylsulfide, carbon disulfide and other sulfides and disulfides, as well as methyl mercaptan, ethyl mercaptan, and other thiols, and other sulfur compounds. Burning of sulfur-containing fuel gas streams is subject to governmental regulation, and it is conventional to use absorbent scrubbing systems to remove a portion of the sulfur contaminants, principally hydrogen sulfide, from fuel gas streams prior to burning to reduce the impact on the environment of such burning.
During 1990, the South Coast Air Quality Management District, an agency in California whose regulations govern, in certain aspects, permissible air emissions by refinery units located in the Los Angeles area basin, passed their Rule 431.1. This Rule has been interpreted to require that, by May, 1993, all fuel gas burned or sold, in areas governed by the Rule, contain no more than 40 PPM total sulfur. Although the requirements of Rule 431.1 have been suspended at August, 1992, such Rule indicates the nature of possible regulatory actions mandating ultra-purification of fuel gases.
To achieve such ultra-purification of fuel gases to reduce total sulfur, an existing refinery could seek to increase reduction of hydrogen sulfide in its fuel gas. This would require expending capital to increase its existing hydrogen sulfide scrubbing unit capacity and absorbent flow rates or to add additional scrubbing units; however, such expenditures will rapidly reach practical limits and each incremental reduction of hydrogen sulfide will be significantly more costly and less effective as to alternatives for overall sulfur reduction. Thus, there is a need for refiners to find cost-effective alternatives to reduction of hydrogen sulfide in fuel gas, which alternatives may include processes for reducing the concentration of other sulfur compounds in fuel gas, such as carbonyl sulfide.
The prior art has not anticipated the need for such ultra-purification of refinery fuel gases, the prior art being focused primarily on treatment of gas streams having a relatively high sulfur content. In particular, the prior art does not address treatment of fuel gas streams having relatively low concentrations of carbonyl sulfide.
It is well known in the art, for instance, that the concentration of hydrogen sulfide in a gas stream can be reduced by scrubbing same with a variety of absorbents, of which the amine solutions are most commercially applied because of their effective reactivity with hydrogen sulfide and the relative ease of regenerating and recycling the amine absorbents. Carbonyl sulfide removal by amine solutions is not so straightforward. Carbonyl sulfide found in relatively low concentrations in fuel gas is substantially inert to absorption when conventional sulfur removal technologies are used.
In addition, high concentrations of carbonyl sulfide may cause a reduction in hydrogen sulfide removal efficiency. It has been reported that carbonyl sulfide impacts hydrogen sulfide recovery by reacting with amine absorption agents to form stable, neutral nitrogen compounds which have no capacity for taking up added amounts of hydrogen sulfide and other absorbable compounds.
Use of amine absorbents for carbonyl sulfide removal has been reported, however, with resulting disputes as to their effectiveness for carbonyl sulfide absorption and related loss of amine base strength during processing caused by amine-carbonyl sulfide reactions which cause deactivation of the absorbents by forming reaction byproducts which are difficult to regenerate and recycle or otherwise impact absorbent activity.
U.S. Pat. No. 2,311,342 to Kerns, et al., relates to method for carbonyl sulfide removal using monoethanolamine. U.S. Pat. No. 2,309,871 to Shultz, et al., and U.S. Pat. No. 2,594,311 to Johnson, et al., also relate to the application of monoethanolamine in gas treatment for carbonyl sulfide removal. U.S. Pat. No. 2,713,077 to Reive relates to removal of carbonyl sulfide from hydrocarbon streams by ion exchange methods. U.S. Pat. No. 2,726,992 to Easthagen, et al., relates to application of diethanolamine as a carbonyl sulfide absorbent. U.S. Pat. No. 3,098,705 to Bally relates to the use of di(isopropanol)amine in carbonyl sulfide extraction. U.S. Pat. No. 3,387,917 to Walles, et al., relates to the extraction of carbonyl sulfide by use of a mixture containing 3-morpholinone compound or an N-alkyl-3-morpholinone compound and an alkanolamine.
U.S. Pat. No. 3,962,015 to Dailey relates to processing of natural gas streams where amine absorbents, including monoethanolamine, diethanolamine and triethanolamine, are used as aqueous based absorbents for carbon dioxide and hydrogen sulfide, where the gas is passed through a low temperature mass absorption zone, a high temperature reaction-absorption zone where carbonyl sulfide in the natural gas is reacted to form hydrogen sulfide and carbon dioxide, and a final low temperature absorption zone, as described in such patent.
Pearce, et al., in "Studies Show Carbonyl Sulfide Problem", Hydrocarbon Processing & Petroleum Refiner, August, 1961, pp. 121-126 reported study results which indicated that monoethanolamine is deactivated by carbonyl sulfide and that diethanolamine is not deactivated by carbonyl sulfide, and reported that carbonyl sulfide hydrolysis to hydrogen sulfide and carbon dioxide, with subsequent reaction with hot potassium carbonate as the absorbent, was the only means of carbonyl sulfide removal for a hot carbonate system.
Unlike natural gas streams which generally have a relatively high carbonyl sulfide content, refinery generated fuel gases, which may be required by regulation to be ultra-purified, may contain relatively low quantities of carbonyl sulfide.
Thus, there is a need for a method of, and an apparatus for, purifying fuel gas streams by reducing the concentration of carbonyl sulfide in such streams, especially when such gas streams already have a relatively low concentration of carbonyl sulfide. In addition, there is a need for a carbonyl sulfide removal process effective with relatively low fuel gas stream flowrate and relatively low content of hydrogen sulfide and carbon dioxide.